Flaring of natural gas in North Dakota in January held steady at 29 percent, right where it has been for the last three months. The good news is that flaring isn’t going up; the bad news is neither is it going down.
In the March Director’s Cut press conference, North Dakota Pipeline Authority Director Justin Kringstad looked at root causes for the flaring of 29 percent of natural gas produced in the state. The press conference is held by the North Dakota Industrial Commission, Department of Mineral Resources, Oil and Gas Division and the pipeline authority.
According to Kringstad, 16 percent of the natural gas that is produced in North Dakota is flared because there is no gas gathering infrastructure in place at the point of production. Another 13 percent is flared in areas where the gathering infrastructure is in place, but there are “challenges,” Kringstad says, in the capability of the existing gathering systems to handle all of the oncoming gas.
Challenges with existing infrastructure
Kringstad says that good progress was made in 2012 on gas connections, and that by the end of the year “we were getting to a point where we were very close to catching up with our well connections.” He says there was a significant dip in new gas connections in January as a result of winter weather, but he is not surprised by that nor is he concerned.
Moving forward Kringstad expects gas connections to again increase, and in the next six to 12 months, reach a point where gas connections are keeping up with new wells. Then the focus, he says, can be on the backlog of wells not connected.
Addressing existing infrastructure
One of the challenges with existing infrastructure, according to Kringstad, is compression. He says when a new high-pressure well comes online it can often kick older, low-pressure wells off of the gathering grid because there is not sufficient compression to handle new gas and the old gas.
In those situations, Kringstad says gas from the older low-pressure wells is again flared. One solution, he says, is more compression, which is accomplished by adding more compressor stations in order to boost line pressure.
A second solution, says Kringstad, is to “loop” existing gathering pipelines, where an additional, parallel line is installed to accommodate higher gas volumes in the system.
The third solution is more frequent “pigging” of the pipelines to push out the natural gas liquids that fall out and settle in the low spots in the pipelines, especially in the winter months. When those NGLs fall out and pool in the pipe, they reduce the volume of pipeline available for gas. In the pigging process, plastic or foam plugs known as “pigs,” are shot through the pipeline and push the pooled liquids out.
“The goal then is to maximize every inch,” Kringstad says. “We need every inch of that pipeline to move gas.”
Kringstad says that because the pigging operations are becoming quite intricate, dedicated crews are being flown in to work two-week shifts just to keep up with the gas because it is so rich.
Gas processing is expected to keep pace with production, so the real challenges are in the gathering systems.
Kringstad says an estimated $4 billion to $5 billion will be spent on current or planned projects over the next several years in North Dakota, both on gas pipelines and processing infrastructure. That number, he says, could double or triple over the next five to 10 years as production increases.
Addressing lack of infrastructure
For the 16 percent of North Dakota’s natural that is flared as a result of no gathering capability, there are two apparent solutions. One is to install gathering systems, which is ongoing in some areas, such as Oneok’s Divide County gathering system and where Bakken Hunter is aligning its well pads with Oneok’s pipelines (see sidebar to this story).
The other solution is to develop and implement alternatives to gathering in areas where gathering infrastructure is not yet in place or is simply not feasible to install.
Oil and Gas Division Director Lynn Helms says the North Dakota Industrial Commission is supporting two flaring bills that are moving through the North Dakota legislative assembly. House Bill 1134 and Senate Bill 2370 would provide incentives to companies to stop gas flaring.
HB 1134 provides incentives for companies to implement other technologies to either utilize or process gas directly at the wellhead. Helms says there has been a lot of talk lately about the importance of providing incentives for removing natural gas liquids from the gas stream and getting those liquids to market.
SB 2370 offers temporary property tax exemptions for gas gathering systems which, per Helms, will incentivize more rapid build-out of gathering systems. That process, however, may not do much more than offset the rising cost of securing pipeline easements, which he says has become a “big business” in western North Dakota.
Sour gas concern
Another flaring concern Helms has is in the situation in which new, high-pressure wells come online and push older, low-pressure wells offline and back into flaring. Some of those older wells produce sour gas, i.e., higher sulfur content gas.
The main problem with the sour gas, according to Helms, is that Oneok’s new Stateline and Garden Creek gas plants were designed for low-sulfur Bakken gas and are not equipped for sulfur removal.
He says those new plants can only accommodate a few parts per million of hydrogen sulfide, whereas traditional North Dakota gas streams are from 1 up to 8 percent hydrogen sulfide.
Older gas plants, such as the Tioga and the Grasslands plants, according to Helms, are equipped to handle the higher sulfur concentrations.
He says Oneok is looking into implementing the capability to redirect gas coming in from the fields to plants that can handle the sulfur, which he calls a “ring” system.
In addition, he says some operators are actually considering installing field facilities to remove the sulfur before the gas enters the pipelines going to the Oneok plants.
Helms says the source of the high-sulfur gas is unknown. Whether the sulfur from the reservoir is somehow related to the way a well is fractured or if it’s from bacteria needs to be investigated, he says.
In the past, sulfur has been seen predominantly in older wells and only in certain areas, but now, Helms says, the sulfur is starting to appear in some new Bakken wells.
If it is just a matter of hydrogen sulfide appearing in an individual well, he says, then that gas can be sweetened before entering the pipeline to the gas plant, but if the hydrogen sulfide is area-wide or field-wide, then he says it “completely changes the dynamic of gathering and treating.”
